1. Field of the Disclosure
The subject disclosure relates generally to recovery of hydrocarbons in subterranean formations, and more particularly to a mechanism for activating a plurality of downhole devices such as when creation of multiple production zones is desired.
2. Background of the Related Art
There are many situations when one would like to selectively activate multiple downhole devices. For example, in typical wellbore operations, various treatment fluids may be pumped into the well and eventually into the formation to restore or enhance the productivity of the well. For example, a non-reactive fracturing fluid may be pumped into the wellbore to initiate and propagate fractures in the formation thus providing flow channels to facilitate movement of the hydrocarbons to the wellbore so that the hydrocarbons may be pumped from the well.
In such fracturing operations, the fracturing fluid is hydraulically injected into a wellbore penetrating the subterranean formation and is forced against the formation strata by pressure. The formation strata is forced to crack and fracture, and a proppant is placed in the fracture by movement of a viscous-fluid containing proppant into the crack in the rock. The resulting fracture, with proppant in place, provides improved flow of the recoverable fluid (i.e., oil, gas or water) into the wellbore. Often, it is desirable to have multiple production zones which are treated differently within the same wellbore. To isolate and treat each zone separately, the prior art mechanisms have been very time consuming and expensive among other drawbacks.
Referring now to FIG. 1, an exemplary layout 10 of valves 12, sleeves 14 and zones 16 to be stimulated is shown. The sleeves 14 are slideably mounted within the valves 12 to selectively open pathways 18. As illustrated, there is one valve 12 per zone 16. Each valve 12 is fixed in place by cement 20 and separated by casings 22. Although only three zones 16 are shown, there may be any desired number of casing valves 12 with sliding sleeves 14 cemented in a well.
Due to the heterogeneous nature of formation, one might not want to open all the valves simultaneously so that the fracturing operations can be performed separately for different layers of formations. The most common embodiment of doing so is using graduated balls or darts to open the valves 12 from the bottom up. For example, the radius of the valves 12, or other restriction such as a protrusion on the sliding sleeve 14, will increase from bottom up. Then, the smallest size ball is first dropped into the well and pumped toward the bottom. The size of the ball is designed so that the ball will pass through all the valves 12 except the bottom, narrowest valve 12. The ball is stopped by the bottom valve 12 so that the sliding sleeve 18 of the bottom valve 12 is pushed to the “open” position to expose the wellbore to cemented formation. Then the fracturing operation through the bottom valve 12 can be executed. After that, the next size larger ball will be dropped to activate the second to bottom valve 12.
The drawbacks of the graduated ball activation system are that there are only a finite number of restrictions/ball sizes that can be implemented. Typical limitations are a 4.5 inch casing at the top with only a minimum of 1 inch at the bottom. Hence, five or six valves across a few hundred feet of depth is the physical limit. Further, the need for restrictions prevents the full-bore access through the valves and the valves have to be activated in a fixed sequence of, in this case, bottom-up. After activation, the balls have to be dissolved or milled to gain access to the sections therebelow, which can lead to a potentially costly intervention.
Another embodiment of valve activation at varying depth utilizes control lines to activate restrictions. Once a restriction in a particular valve is activated, the restriction is then ready to catch a ball or dart dropped from the surface in order to open the respective valve. In these embodiments, common concerns are the possible damage of control lines during run-in-hole, especially in horizontal wells. A damaged control line means that only those lines below the damaged zone can be produced, severely impacting the total potential production from the well, possibly rendering it uneconomical. Another drawback of such designs is that as the thickness of the valve increases, the internal diameter of the valve decreases in order to accommodate the complex hydraulic mechanisms in the valve.